Chinook Energy Inc. Announces Fourth Quarter and 2017 Results

Our operational and financial highlights for the three months and year ended December 31, 2017 are noted below and should be read in conjunction with our consolidated financial statements for the years ended December 31, 2017 and 2016 and our related management’s discussion and analysis which have been posted on the SEDAR website (www.sedar.com) and our website (www.chinookenergyinc.com).

Fourth Quarter and 2017 Financial and Operating Highlights

Three months ended

Year ended

December 31

December 31

2017

2016

2017

2016

OPERATIONS

Production Volumes

Natural gas liquids (boe/d)

551

613

470

637

Natural gas (mcf/d)

19,240

21,548

17,602

24,631

Crude oil (bbl/d)

21

451

22

768

Average daily production (boe/d) (1)

3,779

4,655

3,425

5,510

Sales Prices

Average natural gas liquids price ($/boe)

$

51.87

$

40.70

$

47.89

$

26.35

Average natural gas price ($/mcf)

$

0.99

$

3.31

$

1.95

$

2.06

Average oil price ($/bbl)

$

76.96

$

71.98

$

62.27

$

52.01

Netback(2)

Average commodity pricing ($/boe)

$

13.02

$

27.67

$

16.97

$

19.51

Royalty (expense) recovery ($/boe)

$

(0.08

)

$

(2.84

)

$

0.05

$

(1.19

)

Realized gain (loss) on commodity price contracts ($/boe)

$

3.83

$

(0.35

)

$

3.02

$

0.50

Net production expense ($/boe) (2)

$

(11.06

)

$

(11.88

)

$

(11.57

)

$

(13.61

)

Operating Netback ($/boe) (1) (2)

$

5.71

$

12.59

$

8.45

$

5.21

Wells Drilled (net)

Total natural gas wells drilled (net)

-

2.64

3.63

2.64

Three months ended

Year ended

December 31

December 31

2017

2016

2017

2016

FINANCIAL ($ thousands, except per share amounts)

Petroleum & natural gas revenues, net of royalties

$

4,499

$

10,631

$

21,271

$

36,943

Adjusted funds flow (outflow) (2)

$

1,100

$

1,713

$

4,978

$

(1,004

)

Per share - basic and diluted ($/share)

$

0.01

$

0.01

$

0.02

$

(0.00

)

Net (loss) income

$

(21,160

)

$

6,427

$

(16,914

)

$

(54,773

)

Per share - basic and diluted ($/share)

$

(0.10

)

$

0.03

$

(0.08

)

$

(0.25

)

Capital expenditures

$

7,253

$

4,177

$

39,044

$

9,211

Net (debt) surplus (2)

$

(711

)

$

15,138

$

(711

)

$

15,138

Total assets

$

130,571

$

139,975

$

130,571

$

139,975

Common Shares (thousands)

Weighted average during period

- basic

218,517

216,443

217,174

215,860

- diluted

218,517

216,621

217,174

215,860

Outstanding at period end

223,565

216,443

223,565

216,443

(1) Amounts may not be additive due to rounding.(2) Adjusted funds flow (outflow), adjusted funds flow (outflow) per share, net surplus (debt), operating netback, and net production expense are non-GAAP measures. These terms do not have any standardized meanings as prescribed by IFRS and, therefore, may not be comparable with the calculations of similar measures presented by other companies. See headings entitled “Adjusted Funds Flow (Outflow)”, “Net (Debt) Surplus”, “Operational Netback” and “Net Production Expense” in the Reader Advisory below for further information on such terms.

2017 Highlights

During 2017, we completed the sale of non-core properties in the Knopcik/Pipestone and Gold Creek areas of Alberta for net consideration of approximately $17.8 million after customary closing adjustments. These dispositions marked the completion of our transition to a Montney focused company.

During 2017, we negotiated and secured a demand credit facility as amended with a Canadian chartered bank to increase the availability to $18.0 million which provides us with further financial flexibility.

Our total proved producing reserves increased by 47% from 2016 to 2017.

Our total proved ("1P") reserves increased by 26% from 2016 to 2017 with record low finding and development ("F&D") costs of $6.04/Boe (1P additions replaced 412% of production).

The net present value (NPV 10%) of our 1P and 2P reserves increased 25% and 21% respectively, notwithstanding an average 22% reduction to forecasted five year BC Plantgate gas prices.

Reserves have been booked over only 18% of our approximately 53,200 gross acres (44,350 net acres) of Montney rights in the greater Birley/Umbach area.

During 2017, we drilled four wells (3.63 net) and completed, equipped and tied-in seven wells (6.27 net) at Birley/Umbach.

Our capital investment was $39.0 million during 2017, including $11.5 million to complete our Birley/Umbach compression facility expansion from 25 mmcf/d to 50 mmcf/d, which was commissioned on-time near the end of December 2017.

Upon completion of the latest four new Birley/Umbach wells, the final 24 hour test rates per well averaged 1,800 boe/d including 300 bbl/d of condensate. Two of these wells (1.63 net) came on-stream at the beginning of October 2017; however, due to third party restrictions these new wells are currently flowing at restricted rates.

These four new Birley/Umbach wells were drilled with longer laterals and completed with a new design including more frac stages with less proppant per stage, tighter spacing and using a ‘zipper frac’ technique on parallel well pairs. We anticipate incorporating this new completion design into our future drilling operations. Early production data indicates that these wells have significantly higher free condensate gas ratios which were up 90% compared to the IP30 rates from previously drilled offsetting wells.

During December 2017, we completed the private placement of 6,450,000 common shares on a flow-through basis at a price of $0.31 per flow-through common share for total gross proceeds of $2.0 million.

2018 Recent Highlights

During the first quarter of 2018, we drilled two (2.0 net) vertical exploratory wells in the Birley/Umbach area for $2.1 million. These wells delineated 17 undrilled contiguous sections of 100% owned Montney rights which are located eight kilometres from the nearest well drilled into the Montney. The reservoir quality throughout the entire 235 metre thick Montney zone was evaluated with these wells.

During the first quarter of 2018, we entered into a commodity price contract to fix the Chicago City Gate index price of 6,000 mmbtu/d of natural gas at US$2.68/mmbtu from February 1, 2018 to March 31, 2019.

2017 Financial Results

Our production during the fourth quarter and year ended 2017 averaged 3,779 boe/d and 3,425 boe/d, a decrease of 19% and 38%, respectively, from the same periods of 2016. These production decreases were primarily due to the absence of both the legacy assets of a subsidiary that we acquired late in the second quarter of 2016, and the majority of our Alberta assets that we conveyed to that subsidiary, as a result of the distribution of that subsidiary’s shares to our shareholders late in 2016 (the “Share Distribution”) and various other property dispositions. In addition, an unforeseen pipeline integrity issue on Enbridge’s Oak 16” gathering line (the “Oak Pipeline”) restricted our Birley/Umbach and Martin Creek production in December 2017 through to the date of this news release. Furthermore, for 2017, our volumes were significantly impacted by a longer than scheduled turnaround at the Enbridge McMahon gas plant and other third party restrictions.

Our 2017 operating netback increased 62% to $8.45/boe compared to the same period of 2016. This increase was driven by our lower cash-based cost structure for our Montney assets and the absence of the properties included in the Share Distribution and other property dispositions which had a higher cash-based cost structure. This increase was despite a decrease in our realized commodity pricing. Our realized commodity price decreases generally trended with the decreases in benchmark pricing resulting in a realized price of $16.97/boe for 2017. We realized a record low Station 2 benchmark price during the second half of 2017, not observed in over two decades as attributable to temporary third party pipeline restrictions which are causing an increase in the overall pressure on the BC system and a surplus of natural gas at Station 2. During 2017, we sold approximately 75% of our natural gas production at Station 2 and approximately 25% at the comparably higher Chicago City Gate benchmark compared to selling only 14% of our 2016 natural gas production at Chicago City Gate benchmark. This increase in the 2017 proportion of our sales at the Chicago City Gate benchmark partially offset the decrease in the Station 2 benchmark and we continue to pursue transportation alternatives with more favorable pricing. We realized a recovery of royalties during 2017 of $0.05/boe due to BC Government royalty grants and a gas cost allowance adjustment. Our 2017 net production expense of $11.57/boe decreased from the same period of 2016, despite significantly lower volumes, primarily due to the divestiture of higher cost properties and our lower cost structure Montney properties. However, our net production expense per boe was higher than our expectations due in part to lower production volumes relative to our fixed operating costs.

For the fourth quarter of 2017 (“fourth quarter”), our operating netback decreased 55% to $5.71/boe compared to the same quarter of 2016. This decrease was driven by lower realized commodity pricing despite improvements in each of the other components of the operating netback. Our realized commodity pricing decreases generally trended with the decreases in benchmark pricing which included the significant decrease in the Station 2 benchmark resulting in an average realized price of $13.02/boe for the fourth quarter. Consistent with 2017, our lower proportion of the comparatively higher priced crude oil sales also negatively impacted our realized pricing in the fourth quarter compared to the same quarter of 2016. We realized lower royalties during the fourth quarter compared to the same quarter of 2016 due to BC Government royalty grants. Our other cost improvements are due to the same reasons previously explained.

For 2017, our adjusted funds flow of $5.0 million increased compared to the adjusted funds outflow of $1.0 million during 2016, as a result of higher natural gas liquids pricing and a lower cash-based cost structure for our Montney focused operations. Despite this favorable cost structure, lower realized natural gas pricing and restricted production volumes resulted in the fourth quarter’s adjusted funds flow of $1.1 million decreasing compared to the $1.7 million in the same quarter of 2016. Despite historically low Station 2 benchmark pricing and restricted production volumes, our fourth quarter adjusted funds flow is the sixth consecutive quarter we have reported positive adjusted funds flow which corresponds to when we started our transition to a Montney focused play.

We reported a net loss for 2017 of $16.9 million compared to a net loss of $54.8 million during the same period of 2016. This improvement reflects a lower cost structure associated with our transition to a Montney focused play in addition to higher gains from the disposition of non-core properties and on commodity price contracts. However, partially offsetting these gains were lower natural gas pricing and restricted production volumes. The comparative period of 2016 was also impacted by net losses from our previous subsidiary’s operations whose shares were included in the Share Distribution. These net losses included $58.1 million of impairment charged against the subsidiary’s assets but as partially offset by $20.6 million of net losses attributable to the non-controlling interest.

2017 Operational Results

With the sale of our non-core assets at Gold Creek and Knopcik/Pipestone during the first quarter of 2017, we have completed our transformation into a Montney play focused company. The capital raised from these dispositions as well as cash on hand and adjusted funds flow were used during 2017 to develop our Birley/Umbach property.

During the first quarter of 2017, we completed and tied-in the three wells (2.64 net) (the a-71-F, d-95-F and c-95-F wells) drilled during the fourth quarter of 2016. Total costs for the first three wells, including the fourth quarter of 2016 drilling costs, totalled an average of $3.7 million per gross well.

During the second and third quarters of 2017, we successfully drilled, completed and tied-in our four (3.63 net) horizontal Montney gas wells at Birley/Umbach (the a-81-F, b-90-G, 02/d-5-K and b-14-K wells), with various downhole locations on our D-93-F pad. On average, each well cost $4.6 million gross to drill and complete. The higher average total cost per well incurred on our most recent drilling program, compared to the previous 2016 three (2.64 net) well program, resulted from each well, on average, having 200 metre longer lateral lengths and eight additional completion stages.

Also included in our 2017 capital expenditures was $11.5 million for the expansion of our Birley/Umbach facility to 50 mmcf/d. This expansion was commissioned on-time late in December 2017. The completion of this expansion provides us with the capacity to produce all of our 13 (11.23 net) Birley/Umbach wells, once third party restrictions are resolved, as expected by April 2018.

Gross test results and production from our Birley/Umbach property are as follows(1) (2):

Well

Working Interest (%)

On Production Date

Total Depth (meters)

Drill Time (days)

Lateral Length (metres)

Ports

Frac'd Stages (gross)

Stage Spacing (meters)

Total Gross Cost ($ thousands)

IP30 Gas (mcf/d)

IP30 CGR (bbl/ mmcf)

IP60 Gas (mcf/d)

IP60 CGR (bbl/ mmcf)

IP90 Gas (mcf/d)

IP90 CGR (bbl/ mmcf)

IP120 Gas (mcf/d)

IP120 CGR (bbl/ mmcf)

IP180 Gas (mcf/d)

IP180 CGR (bbl/ mmcf)

IP365 Gas (mcf/d)

IP365 CGR (bbl/ mmcf)

00/A-060-K/094-H-03

74.55

Apr-14

2,700

10

1,204

18

18

67

6,687

3,726

37

3,754

32

3,923

27

3,861

22

3,735

20

3,367

18

00/B-071-F/094-H-03

74.55

Nov-14

2,975

11

1,539

24

23

64

8,398

4,489

14

4,375

11

4,348

9

4,227

9

3,927

7

3,616

8

00/A-073-L/094-H-03

74.55

Mar-15

2,695

10

1,192

18

18

66

7,320

3,712

28

3,417

21

3,459

20

3,376

22

3,076

20

2,625

16

00/C-037-K/094-H-03

100.00

Feb-16

2,670

10

1,210

18

18

67

4,595

4,228

26

4,094

17

3,851

14

3,611

12

3,271

10

2,539

9

00/B-072-F/094-H-03

74.55

Feb-16

2,950

11

1,228

18

18

68

4,701

3,991

21

4,104

15

4,227

12

4,173

10

3,994

9

3,055

7

00/B-004-K/094-H-03

100.00

Feb-16

2,980

11

1,197

18

16

67

4,172

3,364

30

3,082

20

2,921

16

2,764

14

2,530

15

1,993

11

00/A-071-F/094-H-03

74.55

Mar-17

3,235

8

1,457

24

24

61

4,092

3,271

18

3,433

15

3,344

13

3,038

12

2,883

12

N/A

N/A

00/D-095-F/094-H-03

98.20

Mar-17

2,935

9

1,430

24

24

60

4,080

3,404

28

3,554

20

3,454

16

3,457

14

3,306

12

N/A

N/A

00/C-095-F/094-H-03

89.20

Mar-17

3,305

10

1,437

24

24

60

4,125

2,957

19

2,665

16

2,494

15

N/A

N/A

N/A

N/A

N/A

N/A

00/A-081-F/094-H-03

82.44

Oct-17

3,378

9

1,795

35

35

51

4,695

3,862

40

3,905

29

3,565

29

N/A

N/A

N/A

N/A

N/A

N/A

00/B-090-G/094-H-03

80.54

Oct-17

3,530

8

1,798

35

35

51

4,940

3,841

31

4,045

23

3,679

23

N/A

N/A

N/A

N/A

N/A

N/A

02/D-005-K/094-H-03

100.00

Dec-17

3,180

8

1,541

30

30

51

4,229

3,208

47

N/A

N/A

N/A

N/A

N/A

N/A

N/A

N/A

N/A

N/A

00/B-014-K/094-H-03

100.00

Dec-17

3,340

9

1,537

30

30

51

4,439

3,160

51

N/A

N/A

N/A

N/A

N/A

N/A

N/A

N/A

N/A

N/A

(1) Initial production or test rates are not necessarily indicative of long-term performance of the relevant well or fields or of ultimate recovery of hydrocarbons. Well-flow test result data should be considered to be preliminary until a pressure transient analysis and/or well-test interpretation has been carried out. Please see “Initial Productions Rates” under the Reader Advisory section of this news release(2) IP gas and liquids rates shown in the table above are calculated on an average basis which excludes non-producing days.

The growth potential in our Birley/Umbach area is significant, with approximately 53,200 acres (44,350 net) of Montney rights. There are over 290 (242 net) management identified locations (at four horizontal wells per drill spacing unit) in the upper Montney interval alone, with additional potential to develop the middle Montney over the entire land block and the lower Montney in areas with sufficient reservoirs.

Outlook

2017 marked a successful year for us as we moved from delineation to exploitation of our Birley/Umbach property. In early 2014, we drilled our first Montney test well at Birley at a time when others were not entirely convinced of its prospectivity. The results of that test well, along with our follow up wells, confirmed the presence of a large Montney resource and established a large drilling inventory for Chinook. Subsequent to our Birley discovery, we began to streamline our business by divesting of our international assets in Tunisia and transacting on all our non-core Alberta assets through either cash dispositions or share transactions.

Today we are a Montney focused company with a healthy balance sheet. During 2017 we were not able to show the full results and benefits of our newly streamlined operations due to low commodity prices and third party restrictions. Currently, we continue to produce at volumes less than our capability due to gathering system maintenance issues on the Oak Pipeline which are expected to be temporarily resolved by April 2018. In anticipation of weaker natural gas prices, we may voluntarily shut-in volumes through the summer months as we do not have large take or pay commitments that would force us to produce at low prices.

However, we believe that our capital program during the last few years which saw us drill and complete 13 (11.23 net) wells on our Birley/Umbach property as well as our on-time completion of our Birley facility expansion to 50 mmcf/d puts us in an excellent position to accelerate activity when commodity prices recover. We have confirmed the resources are there, now our objective will be to extract them efficiently and profitably. To that effect, although we are encouraged about the results of our exploitation program in 2017 and additional delineation work in 2018, we remain cautious on further capital expenditures until such time as commodity prices improve to a more constructive level. The capital program for the balance of 2018 will be minimal and continuously reviewed by management and the board of directors with adjustments made in response to changing market conditions.

We also believe that consolidation is required and would increase efficiencies among producers and streamline operations. We will continue to pursue opportunities that have the potential to generate additional value to our shareholders.

About Chinook Energy Inc.

Chinook is a Calgary-based public oil and natural gas exploration and development company which is focused on realizing per share growth from its large contiguous Montney liquids-rich natural gas position at Birley/Umbach, British Columbia.

barrel of oil equivalent on the basis of 6 mcf/1 boe for natural gas and 1 bbl/1 boe for crude oil and natural gas liquids (this conversion factor is an industry accepted norm and is not based on either energy content or current prices)

boe/d

barrel of oil equivalent per day

Station 2

Market point for BC natural gas

Chicago City Gate

Market point for eastern US natural gas

Forward-Looking Statements

In the interest of providing our shareholders and readers with information regarding our company, including management's assessment of our future plans and operations, certain statements contained in this news release constitute forward-looking statements or information (collectively "forward-looking statements") within the meaning of applicable securities legislation. Forward-looking statements are typically identified by words such as "anticipate", "continue", "estimate", "expect", "forecast", "may", "will", "project", "could", "plan", "intend", "should", "believe", "outlook", "potential", "target" and similar words suggesting future events or future performance. In particular, this news release contains, without limitation, forward-looking statements pertaining to: that we expect to incorporate our new ‘zipper frac’ completion technique into our future drilling operations, that third party restriction on the Oak Pipeline will be temporarily resolved by April 2018 at which point we will have the capacity to produce all of our 13 (11.23 net) Birley/Umbach wells, that we may voluntarily shut-in volumes throughout the summer months in anticipation of weaker natural gas prices, that our previous capital program has put us in an excellent position to accelerate activity when commodity prices recover, that our capital plan for the remainder of 2018 will be minimal and will be continuously reviewed by management and the board of directors with adjustments made in response to changing market conditions, that we believe that consolidations would increase efficiencies among producers and streamline operations and that we will pursue opportunities that have potential to generate additional value to our shareholders, future exploration and development activities and the timing thereof and how we intend to manage our company. In addition, statements relating to "reserves" are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and can be profitably produced in the future.

With respect to the forward-looking statements contained in this news release, we have made assumptions regarding, among other things: that we will continue to conduct our operations in a manner consistent with that expressed herein, the temporary replacement of the Oak Pipeline by April 2018, no significant future capital expenditure levels, future oil and natural gas prices, future oil and natural gas production levels, future currency, exchange and interest rates, our ability to obtain equipment in a timely manner to carry out exploration and development activities, the ability of the operator of the projects in which we have an interest in to operate in the field in a safe, efficient and effective manner, the impact of increasing competition, field production rates and decline rates, anticipated production volumes, our ability to replace and expand production and reserves through exploration and development activities, certain cost assumptions, that the budgeted capital program for the remainder of 2018, which is subject to the discretion of our Board of Directors, will not be amended in the future, and the continued availability of adequate debt and cash flow to fund our planned expenditures. Although we believe that the expectations reflected in the forward-looking statements contained in this news release, and the assumptions on which such forward-looking statements are made, are reasonable, there can be no assurance that such expectations will prove to be correct. Readers are cautioned not to place undue reliance on forward-looking statements included in this news release, as there can be no assurance that the plans, intentions or expectations upon which the forward-looking statements are based will occur. By their nature, forward-looking statements involve numerous assumptions, known and unknown risks and uncertainties that contribute to the possibility that predictions, forecasts, projections and other forward-looking statements will not occur, which may cause our actual performance and financial results in future periods to differ materially from any estimates or projections of future performance or results expressed or implied by such forward-looking statements. These risks and uncertainties include, without limitation, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, loss of markets, volatility of commodity prices and currency fluctuations, our Board of Directors may amend the capital program for the remainder of 2018 based on its discretion; environmental risks, competition from other producers, inability to retain drilling rigs and other services, unanticipated increases in or unforeseen capital expenditure costs, including drilling, completion and facilities costs, unexpected decline rates in wells, delays in projects and/or operations resulting from surface conditions, wells not performing as expected, delays resulting from or inability to obtain the required regulatory approvals and inability to access sufficient capital from internal and external sources. As a consequence, actual results may differ materially from those anticipated in the forward-looking statements. Readers are cautioned that the forgoing list of factors is not exhaustive. Additional information on these and other factors that could affect our operations and financial results are included in reports on file with Canadian securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com) and at our website (www.chinookenergyinc.com). Furthermore, the forward-looking statements contained in this news release are made as at the date of this news release and we do not undertake any obligation to update publicly or to revise any of the forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws.

Operating Netback

The reader is cautioned that this news release contains the term operating netback, which is not a recognized measure under IFRS and is calculated as a period’s sales of petroleum and natural gas, net of realized gains or losses on commodity price contracts, royalties and net production expenses, divided by the period’s sales volumes. We use this non-GAAP measure to assist us in understanding our production profitability relative to current and fixed commodity prices and it provides an analytical tool to benchmark changes in field operational performance against prior periods. Readers are cautioned, however, that this measure should not be construed as an alternative to other terms such as net income determined in accordance with IFRS as a measure of performance. Our method of calculating this measure may differ from other companies, and accordingly, it may not be comparable to measures used by other companies.

Net Production Expense

The reader is cautioned that this news release contains the term net production expense, which is not a recognized measure under IFRS and is calculated as production and operating expense less processing and gathering income. We use net production expense to determine the current periods' cash cost of operating expenses and net production and operating expense per boe is used to measure operating efficiency on a comparative basis. Our method of calculating this measure may differ from other companies, and accordingly, it may not be comparable to measures used by other companies.

Adjusted Funds Flow (Outflow)

The reader is cautioned that this news release contains the term adjusted funds flow (outflow), which is not a recognized measure under IFRS and is calculated from cash flow from operations adjusted for changes in non-cash working capital related to operations, exploration and evaluation expenses related to operations, provision expenditures related to operations and severance/transaction costs. We believe that adjusted funds flow (outflow) is a key measure to assess our ability to finance capital expenditures and when debt is drawn, debt repayments. Adjusted funds flow (outflow) is not intended to represent cash flow from operating activities, net earnings or other measures of financial performance calculated in accordance with IFRS and should not be construed as an alternative to, or more meaningful than, cash flow from operating activities as determined in accordance with IFRS as an indicator of our financial performance. Our method of calculating this measure may differ from other companies, and accordingly, it may not be comparable to measures used by other companies. Adjustments to cash flow from operations are for changes in non-cash operating working capital which are expected to reverse and for those costs that are not directly caused by lifting production volumes.

Net (Debt) Surplus

The reader is cautioned that this news release contains the term net (debt) surplus, which is not a recognized measure under IFRS and is calculated as bank debt adjusted for current assets less current liabilities as they appear on the balance sheets, both of which exclude mark-to-market derivative contracts and assets and liabilities held for sale and current liabilities excludes any current portion of debt, deferred customer obligations and provisions. We use net (debt) surplus to assist us in understanding our liquidity at specific points in time. We exclude the current portion of provisions and the deferred customer obligation as they are not financial instruments. Mark-to-market derivative contracts and assets and liabilities held for sale are excluded as they are unrealized.

Future Oriented Financial Information

This news release may contain Future Oriented Financial Information ("FOFI") within the meaning of applicable securities laws. The FOFI has been prepared by our management to provide an outlook of our activities and results and may not be appropriate for other purposes. The FOFI has been prepared based on a number of assumptions including the assumptions discussed under the heading "Forward-Looking Statements" and assumptions with respect to production rates and commodity prices. The actual results of our operations and the resulting financial results may vary from the amounts set forth herein, and such variations may be material. Our management believes that the FOFI has been prepared on a reasonable basis, reflecting management's best estimates and judgments.

Barrels of Oil Equivalent

Barrels of oil equivalent (boe) is calculated using the conversion factor of 6 mcf (thousand cubic feet) of natural gas being equivalent to one barrel of oil. Boes may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf:1 bbl (barrel) is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.

Initial Production Rates

Any reference in this news release to initial, early and/or test or production/performance rates (including IP30, IP60, IP90, IP120, IP180, and IP365) are useful in confirming the presence of hydrocarbons, however, such rates are not determinative of the rates at which such wells will continue production and decline thereafter. Additionally, such rates may also include recovered "load oil" fluids used in well completion stimulation. While encouraging, readers are cautioned not to place reliance on such rates in calculating our aggregate production. The initial production or test rates may be estimated based on other third party estimates or limited data available at this time. In all cases in this news release initial production or test rates are not necessarily indicative of long-term performance of the relevant well or fields or of ultimate recovery of hydrocarbons. Well-flow test result data should be considered to be preliminary until a pressure transient analysis and/or well-test interpretation has been carried out.